Seismic migration using offset checkshot data

ABSTRACT

A method of migrating seismic data using offset checkshot survey measurements. The offset checkshot survey measurements involve raypaths similar to the migration raypaths for the seismic data, and are used to determine direct arrival traveltimes to receivers in a borehole. Embodiments of the invention provide for direct use of the traveltimes in migration, or indirect use of the traveltimes in migration via construction of a migration velocity model. The velocity model embodiments further provide for either traveltime error correction via use of interpolated error functions or construction of migration error tables. The invention can be employed for time, depth or Kirchhoff migration, in either two or three dimension, and in either prestack or poststack applications.

This application is a continuation of application Ser. No. 08/325,854,filed Oct. 19, 1994, now abandoned.

FIELD OF THE INVENTION

This invention relates to a method of geophysical prospecting whichimproves the accuracy of seismic migration. Specifically, the inventionuses offset checkshot survey measurements to accurately migratereflectors present in conventional two-dimensional and three-dimensionalsurface seismic data.

BACKGROUND OF THE INVENTION

In seismic exploration, energy imparted into the earth by a seismicsource reflects from subsurface geophysical features and is recorded bya multiplicity of receivers. This process is repeated numerous times,using source and receiver configurations which may either form a line(2-D acquisition) or cover an area (3-D acquisition). The data whichresults is processed to produce an image of the reflector using aprocedure known as migration.

Seismic data migration typically uses diffraction traveltimes fromsubsurface imaging points to the source and receiver locations toproduce an image of the subsurface reflectors. The diffractiontraveltimes are the seismic signal propagation times along raypaths fromeach imaging point to the source and receiver locations. The propagationtimes, which are usually plotted as diffraction traveltime curves, areused after appropriate preprocessing of the raw seismic data to generatean estimate of the correct location of the reflector. The migrationprocess will be familiar to those versed in the art.

Incorrect diffraction traveltime curves lead to at least two undesirablemigration consequences. First, the image of the reflector which resultswill be poorly focused, making interpretation difficult. Second, thereflector may be mispositioned, a serious drawback in oil and gasexploration where accurate mapping of the subsurface structure isimportant. The effects of poor focusing and improper positioning areparticularly apparent when migrating steeply dipping reflectors or whenmigrating in areas having significant lateral velocity variations.

In conventional practice, an estimated subsurface velocity model is usedto generate the diffraction traveltime curves. One common method ofestimating that model is to analyze seismic data corresponding toraypaths which are inclined less than about 450 with respect to thevertical. The velocities can be determined by analyzing the variation inreflection traveltime as a function of distance between sources andreceivers in the surface data. Because the near vertical raypaths areshorter than more nearly horizontal raypaths, the traveltimes are lesssensitive to velocity errors and to lateral or vertical velocityvariation. Unfortunately, accurate migration of steeply dippingreflectors, such as salt flanks and faults, also requires accuratetraveltimes for raypaths that are closer to horizontal.

Another method that is used to obtain migration velocities is toprestack migrate several subsets of the surface seismic data. This iscommonly done using either common-shot, common-offset orcommon-depth-point gathers. The migration is performed with an initialvelocity model obtained from conventional normal moveout velocityanalysis. If the migrations produce images that are consistent, theinitial velocity model is taken to be correct. Otherwise, the velocitymodel is updated to give a model that gives a better migration. Severaliterations are usually required to obtain a consistent migrated image.Variations of this method include depth focusing analysis and migrationvelocity sweeps.

Reflection tomography can also be used to determine migration velocitiesfrom surface seismic data. Reflection events on unstacked surfaceseismic data are first digitized. A gridded model of the subsurface isthen optimized to give the best fit to the observed traveltimes.Unfortunately, surface seismic data do not contain enough information touniquely specify both a migration velocity model and the reflectorgeometries. As a result, the derived velocity model may be ambiguous orgeologically unreasonable. Improvements can be made by applyingconstraints to the optimization process, but those constraints generallyreduce or eliminate the ambiguities at the expense of poorer fits to thetraveltime data.

Vertical checkshot data and well sonic logs are also commonly used forobtaining a migration velocity model. Vertical checkshot data aregathered by placing a receiver in a well and measuring first arrivaltravel times from a source placed vertically above the receiver. Thesedata are typically gathered at depth intervals in the well of 250 to 500feet. Velocities can be determined from the checkshot data by dividingthe distance between adjacent receivers by their associated traveltimes.Vertical checkshots therefore measure only the vertical velocity.Migrating the seismic data with the vertical checkshot velocityguarantees that reflections from nearly horizontal reflectors will beaccurately imaged at the well. Unfortunately, a velocity that givessmall traveltime errors for vertical raypaths may produce much largererrors for horizontal raypaths.

Sonic logs, like vertical checkshot surveys, measure verticalvelocities. As a result, steeply dipping reflectors may bemispositioned. In addition, sonic logs suffer from the additionaldrawback that the velocity measurements are made at higher frequenciesthan are normally present in seismic data. Due to velocity dispersion(i.e. the variation of velocity with frequency), those frequencies arehigher than are appropriate for migrating seismic data.

None of the above methods for determination of migration velocitiesaccount for velocity anisotropy (the variation of velocity with respectto the propagation angle of a raypath). Anisotropy is frequently presentin seismic data as a higher order term in the diffraction eventtime-offset curves. Although a reasonably good match to observed seismicdata can usually be obtained from an isotropic migration velocity model,for example the migrated images may be reasonably well-focused andconsistent, the reflectors may nevertheless be mispositioned. Typically,any such mispositioning results from the fact that reflections fromsteep features have raypaths involving a large range of propagationangles, each of which may have velocities not taken into account by theisotropic model. In such cases additional information must be used todetermine an anisotropic velocity model. This is generally a difficulttask, given that even in laterally homogeneous media the higher orderterm may be hard to separate from terms associated with verticalinhomogeneities. In addition, conventional migration software does notusually account for anisotropy even if a reasonable anisotropic velocitymodel were available. As a result, conventional processing often suffersfrom an inability to accurately image steeply dipping reflections inregions having anisotropic media.

Migration velocities can also be estimated from vertical seismic profile(VSP) data gathered with sources at a range of offsets from the well.Optimization methods referred to as traveltime tomography are used todetermine a velocity model. Unfortunately, the velocity model obtainedfrom traveltime tomography suffers from the non-uniqueness problemsimilar to that which occurs in reflection tomography. In addition, themodel produces a good migration at the well but degrades in imagequality elsewhere. As in reflection tomography, imposition ofconstraints during the optimization reduces the ambiguities and producesgeologically reasonable models at the expense of a poorer match to thetraveltime data.

Migrated images may also be of poor quality as a result of the manner inwhich the traveltime curves are processed by the migration routines.Many migration programs, particularly those using the Kirchhoff method,sum the seismic data along traveltime curves corresponding to the firstarrival only, and ignore subsequent arrivals. However, lateral velocitygradients and some geologic structures can lead to multivalueddiffraction traveltimes, each of which may be important, or any one ofwhich may be more important than the first arrival. In particular, laterarrivals may carry more of the seismic energy than does the firstarrival. If the migration ignores or mishandles the later arrivals, poorquality images will result.

Another constraint of some migration routines deals with the ability tomigrate all points on the diffraction traveltime curve. Some routinesare limited in the capacity to accurately migrate the entire curve. Insuch cases, it is preferable to migrate with traveltimes that are asaccurate as possible for diffraction raypaths corresponding to thereflector dips of greatest interest. Those dips are often the steeplydipping reflectors, which are more sensitive to horizontal velocityerrors than are horizontal reflectors. As noted, however, horizontalvelocities are generally poorly characterized in conventional velocitymodels.

Once a diffraction traveltime curve has been derived and the seismicdata has been migrated, it is useful for the data analyst to have anestimate of the accuracy of the position of the reflector in themigrated image. Conventionally, that estimate is obtained by correlatingborehole measurements, such as from sonic logs or dipmeters, with theimage. High correlations indicate an accurate migration.

There are several limitations to the correlation approach however. Apoor correlation with borehole data may indicate migration error, butdoes not quantify that error. In addition, other problems, such asinaccurate estimation of the seismic wavelet, can lead to poorcorrelation between well data and a seismic image. And finally, a goodcorrelation between well data and the shallow dipping reflectors in theimage does not necessarily imply that the steep dips are accuratelymigrated. In particular, because wells do not always penetrate steeplydipping reflectors, such as the flanks of salt domes, the correlationsare not meaningful at the locations in which the greatest accuracy isdesired. Because hydrocarbon reserve estimates can be quite sensitive tothe position of the steeply dipping reflectors, the correlations areoften of limited value to the analyst.

Fundamental to this entire discussion of conventional practice relatingto the development of diffraction traveltimes is the reliance on thevelocity model as the desired or preferred input to the migrationprocess. However, velocities are neither the fundamental parametersrequired for migration, nor the parameters directly obtained from fieldmeasurements. Rather, traveltimes are the underlying parameters on whichmigration accuracy relies, and the traveltimes associated with theraypaths for a family of source and receiver configurations are theparameters directly obtained in the field. Procedures which rely moredirectly on traveltimes as a migration input would reduce errorsderiving from the use of velocity models, and are therefore desiredwithin industry.

From the foregoing, it can be seen that there is a need for a method ofgenerating diffraction traveltimes for use in seismic migration whichgives improved accuracy for near-horizontal raypaths, which can handlevelocity anisotropy, and which takes into account multivalued traveltimecurves. Preferably, the method should rely on measured diffractionraypath traveltimes to provide for accurate migration of seismic data,either directly as an input to migration or indirectly by improving theaccuracy of the input velocity model. The method should also provide fora quantitative estimate of any migration error. The present inventionsatisfies these needs.

SUMMARY OF THE INVENTION

This invention overcomes the above limitations of the prior art by usingoffset checkshot survey data gathered from a region adjacent to asubsurface feature to be imaged to determine a migration velocity model,migration traveltimes, or both. The offset checkshot survey involvessurface sources and borehole receivers placed in a geometry whichresults in raypaths geometrically similar to the raypaths in the seismicdata to be used in imaging the feature. The offset checkshot survey datanot only allows for accurate migration of the seismic data, but alsoleads to embodiments of the present invention in which migration errorestimates may be calculated.

The embodiment of the invention to be implemented in a specific analysisdepends on the nature of that analysis and on the characteristics of theregion adjacent to the feature. For example, one embodiment of theinvention can be used to generate a reflector-weighted migrationvelocity model to allow accurate migration of the reflector dips ofgreatest interest. That embodiment would be most appropriate for aregion characterized by laterally invariant migration velocities or foran analysis involving time migration. If the migration velocity islaterally varying, depth migration is likely to be involved and thepresent invention can be used to develop an optimized migration velocitymodel for all dips. Both of these embodiments also enable the analyst todetermine the positioning error of the reflectors in the migrated image.

For traveltime migration, embodiments of the invention exist which allowboth conventional and model-guided traveltime interpolation. Theseembodiments are appropriate for Kirchhoff-type migrations, which aremore expensive than time or depth migration, but which are also moreaccurate.

The invention can be applied to both two dimensional and threedimensional migration. In addition, either prestack or poststackembodiments of the invention can be employed.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention and its advantages will be more easily understoodby reference to the following detailed description and the attacheddrawings in which:

FIG. 1 shows the geometry of source and receiver positions which areconventionally used to determine traveltimes and velocity models formigration of seismic data;

FIG. 2 shows the geometry of source and receiver positions used in thepresent invention to determine migration traveltimes and migration errortables;

FIG. 3 schematically illustrates the steps required to implementembodiments of the present invention where the chosen migration routineuses a velocity model as an input;

FIG. 4 depicts the raytracing method used to determine the sourcelocations of principal interest in developing a weighted velocity modelfor a time migration embodiment of the present invention;

FIG. 5A depicts a traveltime curve derived from common receiver-sortedtraveltime data;

FIG. 5B depicts a method of determining migration error using offsetcheckshot data;

FIG. 6 schematically illustrates the steps required to implementembodiments of the present invention where the chosen migration routineuses traveltimes as an input;

FIG. 7 depicts a plan view of a checkshot source grid for use in amulti-borehole traveltime migration embodiment of the present invention;and

FIG. 8 depicts two methods of interpolating traveltime error for use incorrecting the image location of a traveltime migration embodiment ofthe present invention.

While the invention will be described in connection with its preferredembodiments, it will be understood that the invention is not limitedthereto. On the contrary, it is intended to cover all alternatives,modifications, and equivalents that may be included within the spiritand scope of the invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention is a method of migrating seismic data using offsetcheckshot survey (OCS) data. The method uses OCS data to accuratelydetermine diffraction traveltimes which, either directly or indirectly,are required inputs to seismic migration routines. The method alsoprovides for use of the OCS data to generate a table of migration erroras a function of migrated location and dip. These two attributes of thepresent invention thereby allow geologic interpreters to determine thesubsurface location of migrated seismic images more accurately than hasheretofore been possible.

As discussed above, tomographic methods are frequently used to derivemigration velocity models. However, those methods may produce velocitymodels with significant differences between measured and modeledtraveltimes, or which may be geologically unreasonable. In addition,conventional tomography makes no attempt to control the distribution oftraveltime errors produced by model. This invention provides severalsolutions to these problems.

First, the invention has the capability of determining the combinationsof sources and receivers which most significantly contribute to theimage of any given reflector dip. For example, migrated images are oftenmore sensitive to traveltime errors for nearly horizontal raypaths,which are not generally used to generate velocity models, than totraveltime errors for nearly vertical raypaths. In addition to the moreaccurately reproduced horizontal raypath traveltimes, the inventionenables the traveltimes corresponding to specific sources and receiversto be weighted in the tomographic reconstruction of the velocity model.Those sources and receivers are preselected to give improved accuracy inthe migration of the reflector dips of highest interest. This representsan improvement on conventional methods in which either all data areweighted equally or the data are weighted based merely on an assumedconfidence level in the traveltime measurement.

Second, if tomography does not produce a satisfactory velocity model,the invention can be used to quantify the migration error that willresult from the migration. The error estimates can be used to improvethe accuracy of the geological interpretations made based on thevelocity model. No prior techniques exist which allow such aquantification of migration error.

Finally, some migration routines accept diffraction traveltimesdirectly. In this invention, offset checkshot traveltimes can bedirectly input into those routines without the necessity of producing avelocity model. Because the checkshot raypaths accurately measuretraveltimes from the surface to the borehole, the result is an imagethat is accurate at the borehole for all dips. The invention includesembodiments which allow conventional and model-guided interpolation ofdiffraction traveltimes.

FIGS. 1 and 2 compare seismic source and receiver configurations of oneembodiment of the present invention (FIG. 2) to the prior art (FIG. 1).In both figures, the earth's surface 2, which overlies a geophysicalfeature 4, steeply dipping reflectors 7, and a plurality of generallyhorizontal reflectors 6, is penetrated by borehole 8.

FIG. 1 depicts two techniques which are used in the prior art to developvelocity models and diffraction traveltime curves. The first techniqueis to use a vertical checkshot source 10, positioned on surface 2adjacent to borehole 8, to generate signals along raypaths 11.Velocities and traveltimes associated with raypaths 11 are determinedfrom analysis of the direct arrivals at receivers 12. A secondconventional technique, also depicted in FIG. 1, involves use of afamily of surface sources 14 and a family of surface receivers 16.Sources 14 generate signals which travel along raypaths 15a and 15b andreflect from reflectors 6 before being received by receivers 16. Byanalyzing the variation of reflection traveltime as a function ofdistance between sources 14 and receivers 16, average migrationvelocities and traveltimes can be determined.

Advantages of the present invention are demonstrated in FIG. 2, whichdepicts migration raypaths 17 as well as offset checkshot raypaths 19.Migration raypaths 17 derive from processing of the surface seismic datato be used to image feature 4 and reflectors 7 (sources and receiverscorresponding to that surface seismic data are not shown). Offsetcheckshot raypaths 19 derive from offset checkshot survey sources 18which generate signals received by offset checkshot receivers 20.

The OCS sources are located along surface 2 such that raypaths 19 aregenerally horizontal near borehole 8, which thereby leads to a geometricsimilarity between raypaths 19 and raypaths 17. As a result of thatgeometric similarity, traveltimes and velocity models which derive fromraypaths 19 more accurately characterize the traveltimes and velocitieswhich are required for migration along raypaths 17 than do thetraveltimes and velocity models which result from raypaths 11, 15a, and15b in FIG. 1. In addition, as is well known in the art, horizontallytraveling raypaths are necessary to accurately develop a migrated imageof steeply dipping features such as feature 4 and reflectors 7. Incontrast, raypaths 11, 15a, and 15b are essentially vertical. Althoughvertical velocities and traveltimes are well characterized by raypaths11, 15a, and 15b, horizontal variations, such as result from anisotropy,are not well characterized, thus leading to inaccuracies in the migratedimages. By including raypaths with horizontal components, the presentinvention minimizes or entirely eliminates those inaccuracies.

The range along surface 2 over which the checkshot sources should beplaced will be a function of the expected characteristics of feature 4and reflectors 7. As is well known in the art, that range, which is alsoreferred to as the migration aperture, is preferably large relative tothe steepest dip of interest in the migration. Ranges up to two or threetimes as long as the depth of borehole 8 may be desirable, or evenlonger, depending on the application of the present method. However, anoverly large aperture can lead to excessive computer time costs, and mayalso increase the noise level in the migrated image. The considerationsrequired in determining an appropriate migration aperture will be wellknown to those skilled in the art.

The data gathering geometry for the offset checkshot configuration ofFIG. 2 is similar to the geometry used for vertical seismic profile(VSP) data. However, the offset checkshot data are used only to measuredirect arrival traveltimes from sources 18 to receivers 20. In contrast,VSP data are generally used to measure both the direct arrival and thereflected arrivals of feature 4 and reflectors 7. In the OCS data,because only direct arrival traveltimes are measured, thesignal-to-noise ratio for the offset checkshot data does not have to beas large as is typically required to facilitate processing of VSP andreflected arrivals. This lower signal-to-noise ratio advantage of theoffset checkshot survey data offers cost benefits as compared toconventional practice. For example, receivers deployed in productiontubing should be able to acquire satisfactory data. This eliminates thecost of removing the tubing, which can be up to $1,000,000 for someboreholes.

In addition, the offset checkshot data can be gathered by hydrophonesrather than geophones. Hydrophones typically have lower signal-to-noiseratio reception capabilities than geophones and are therefore often oflimited use in VSP data acquisition. However, as noted above,signal-to-noise ratio is not a constraint of the present invention. Inaddition, it is generally easier to deploy a large number of hydrophonesin a borehole, if desired, than it is to deploy a similar number ofgeophones. Therefore, offset checkshot data could be acquired atnumerous depths more easily using hydrophones.

FIG. 3 depicts a flowchart of an embodiment of the present invention.Initially, offset checkshot data 40 are gathered, such as is depicted inFIG. 2. Because these data are only used to determine traveltimes, thespatial aliasing criteria, which as is well known must be met to imagereflectors, does not need to be satisfied. This attribute of the presentinvention allows surface sources 18 and borehole receivers 20 to berelatively sparsely spaced, thus lowering data acquisition cost. Forexample, a spacing of approximately 150 meters may be sufficient, ascompared to conventional borehole spacings of 15 meters. This attributeof the present invention also facilitates acquisition of data over abroad range of distances along surface 2, since lower total costs willbe involved in acquiring data over a relatively large range than wouldbe involved in conventional VSP data acquisition.

In step 42 of FIG. 3, the direct arrival traveltimes are selected fromthe data and are digitized. This step will be well known to thoseskilled in the art.

Step 44 requires a decision be made on the specific objectives of themigration that is to be performed. This decision is necessary becausethe embodiment of the present invention which is to be employed may varyas a result of those objectives. Among the considerations involved arethe goals of the overall data analysis effort, the expectedcharacteristics of the subsurface region, and the cost and accuracyspecifications which the migrated image must meet. These considerations,which will be well known to those skilled in the art, are most clearlydemonstrated by discussing step 44 in conjunction with steps 46 and 52,as follows.

An analyst's decision at step 44 to invoke a relatively low costmigration routine will generally lead to selection of a migrationroutine using a velocity model at step 46. Examples of such routinesinclude many frequency-wavenumber and finite difference methods forsolving the migration wave equation. Another consideration which maylead to velocity model migration is the assumption that the region to bemodeled is isotropic.

Alternatively, if the analyst opts at step 44 not to explicitly assumean isotropic medium, or requires a more accurate output result whichwill generally be at higher cost, the migration routine would involvetraveltime inputs, and the analyst's decision at step 46 will followpath 48 (continuing on FIG. 6). For example, Kirchhoff migration methodsgenerally accept traveltime inputs directly. The analyses required todetermine which migration option is most appropriate or is mostdesirable under specific circumstances for a given set of seismic datawill be well known those skilled in the art. Whether velocity ortraveltime inputs are involved, the present invention can be implementedin either a prestack or poststack mode for both two dimensional andthree dimensional migration. The present invention provides improvedresults for each of these migration decisions, as is discussed furtherbelow.

If the desired migration routine involves a velocity model analysis, viapath 50 on FIG. 3, the analyst must decide at step 52 whether to usetime or depth migration.

Time migration (path 56) assumes migration velocities are laterallyinvariant. As a result, time migration software is less expensive to usethan migration programs that attempt to handle lateral velocityvariations, such as depth migration. The limitation of that assumption,however, is that a velocity model cannot generally be specified whichaccurately migrates all dips present in the seismic data. For thatreason, time migration may be used, as an example, in the proximity ofsalt domes where accurate migration of a steeply dipping salt face ismore important than is accurate migration of the sediments surroundingthe salt. In such applications, the present invention provides a methodof finding a velocity model that accurately migrates reflector dips ofgreatest interest, and in addition provides a measurement of migrationerror for other dips.

If time migration is to be performed, via path 56, the analyst must nextselect the reflector dips that are of principal interest, step 58.Typically, these would be fairly steep dip reflectors, such asreflectors 7 in FIG. 2, since time migration of flat layers isrelatively insensitive to velocity errors. For each receiver in theoffset checkshot survey, source locations corresponding to raypaths fromthe reflector dips of interest are determined, step 60. As depicted inFIG. 4, source locations 24 are determined by selecting a location 21 oneach reflector 7 specified in step 58, and by tracing a raypath 23 backto surface 2 using an initial estimate of the migration velocity model(not shown). Location 21 is a tangent to reflector 7 at the position ofreceiver 20. Raypath 23 departs location 21 at a perpendicular 22 toreflector 7. The desired source location 24 is the point at whichraypath 23 intersects surface 2. Techniques for performing ray tracingare well known in the art.

Next, in step 62, weights for the offset checkshot traveltimemeasurements must be determined. Traveltimes for offset checkshotsources (not shown) near source location 24 in FIG. 4 are givenrelatively high weights, while those offset checkshot sources at anincreasing distance from the source location are less heavily weighted.The purpose of the weights is to ensure that the subsequently derivedvelocity model produces traveltimes that are most accurate for the dipsand raypaths of principal interest, such as reflectors 7 and raypath 23in FIG. 4, since, as indicated above, determining a velocity modelaccurate for all possible dips and raypaths is often difficult orimpossible. Satisfactory values for the weights are determined by trialand error, based among other factors on the nature of the dips ofhighest interest, the quality and quantity of the OCS data, and possiblyalso on the expected nature of the velocity characteristics of theregion through which the raypaths pass. The considerations required todetermine appropriate weights will be known to those skilled in the art.

A tomographic inversion of the traveltimes is performed in step 64 toderive an updated migration velocity model. The inversion assumes thevelocity model is laterally invariant, as is required for timemigration, and uses the weighted traveltime measurements from step 62.In addition, other available traveltime data may also be used in theinversion, and may or may not be included in the step 62 weightingprocedure, depending on the nature of the other available data and ofthe dips to be optimally migrated. Parameters may also be included inthe inversion to allow determination of a horizontal coordinate stretchfactor to compensate for velocity anisotropy. The stretch factor is anartificial scale factor that is applied to the horizontal coordinates ofthe sources and receivers, and can be used to simulate anisotropicmigration with an isotropic migration routine. Use of such a stretchfactor will allow a larger range of traveltimes to be accuratelypredicted, and will increase the migration accuracy for a larger rangeof dips. If such a stretch factor is employed, it is also applied to thehorizontal coordinates of the surface seismic data. Coordinate scalefactors are well known in data analysis, and stretch factors havepreviously been used in industry for analysis of VSP data.

The surface seismic data are time migrated in step 66 using themigration velocity model from step 64. If a horizontal coordinatestretch factor was applied in step 64, the horizontal coordinates of themigrated image are divided by that factor to determine the correctlyscaled image.

As will be understood to those skilled in the art, two separate velocitymodels are often employed during the processing of seismic data. A firstvelocity model is used to perform the time migration of the seismicdata. That migration results in a seismic image with a time-referencedscale. The second model is used to convert the time-reference to depthunits. Two velocity models are used in this processing sequence tooptimize the processing result. The first model is derived from thesurface seismic data which is to be migrated. However, that model willnot generally involve a direct reference to absolute depth units. Incontrast, the second model is preferably based on data gathered fromboreholes, thereby including a depth reference. As is well known in theart, the two models are often quite different, for example due toanisotropy.

An advantage of the OCS data is that both an optimal migration velocitymodel and an optimal depth conversion velocity model can be obtainedsimultaneously. As described above, a tomographic inversion of thetraveltimes is performed to obtain a migration velocity model. As partof that inversion, an inversion for the depths of the OCS receivers isalso performed. This receiver depth inversion results in a velocitymodel with a closer fit to the measured traveltimes than is generallypossible if measured receiver depths are used. As part of the receiverdepth inversion, vertical stretch parameters may be used to improve theinversion fit to the measured data. These parameters increase thelikelihood that the model will accurately characterize the OCS data, andtherefore increase the accuracy of the migrated image. As above, thevelocity model which results is used to time migrate the seismic data.The depth conversion is performed using the velocity/depth relationshipwhich also results from the inversion. This two-part inversion ensuresan optimal depth image, because the migration is performed with avelocity which reproduces the measured traveltimes as closely aspossible, and because that velocity also contains as accurate a depthreference as possible. An advantage of the present method is that theoptimal depth image is obtained without the prior art's commonrequirement of employing two separate velocity models.

The result at step 68 is an image which is accurate at the borehole forthe dips of principal interest which were selected in step 58. Dipsadjacent to the dips of principal interest will also be accuratelymigrated, with the range of accuracy corresponding to the range aroundthe borehole in which the assumption of lateral invariance is valid. Atother dips, however, the image may be incorrectly located. Steps 76through 86 provide an embodiment of the invention which allows thaterror to be quantified, however, as follows.

FIGS. 3, 5A and 5B demonstrate the use of an embodiment of the presentinvention to calculate migration error when a velocity model is used inthe migration. After the offset checkshot data are gathered, step 40,and the traveltimes are digitized, step 42, the checkshot data aresorted into common receiver order, step 76. The sorted data allowgeneration of traveltime curves such as are depicted in FIG. 5A. In thatfigure the traveltimes corresponding to one receiver are plotted as afunction of all checkshot sources, thus leading to the title commonreceiver-sorted traveltime curve. For each source-receiver pair, step 78in FIG. 3, the time dip on the traveltime curve is measured, step 80. Asshown in FIG. 5A, time dip 26 is merely the slope of a tangent to curve25 for the selected source.

Using the migration velocity model from step 64, step 82 involvestracing a raypath from the surface using the time dip from step 80. Asshown in FIG. 5B, migration raypath 17 is traced through the velocitymodel from the surface location of each offset checkshot source usingthe corresponding time dip 26 until the raypath's traveltime is equal tothe measured offset checkshot traveltime for the chosen source-receiverpair. The raypath is called the migration raypath because it defines thelocation and dip to which the measured time dip will move aftermigration.

The reflector location and dip corresponding to migration raypath 17 isa plane 30 that is perpendicular to the endpoint of raypath 17. If themigration velocity model is accurate, the location of plane 30 willcoincide with the position of the borehole receiver 20 which was pairedwith the source in step 78 of FIG. 3. In that situation migrationraypath 17 and checkshot raypath 19 will coincide. If the model isinaccurate, the migration error for the reflector location and dip canbe determined from vector 28, which is drawn from receiver 20 to theendpoint of migration raypath 17. Vector 28 determines the reflectorlocation error resulting from the inaccuracy in the velocity model. Thespatial orientation of plane 30 determines the dip error resulting fromthe inaccuracy in the velocity model.

This procedure is repeated in step 78 for all source-receiver pairs,resulting at step 86 in generation of an output table of migration erroras a function of migrated location and dip. Combined with the results ofthe time migration application of this embodiment of the presentinvention, step 68 in FIG. 3, this migration error table provides bothan accurate time migration of the reflector dips chosen in step 58 and aquantification of the migration error for all other reflector dips. Thegeologic interpreter can use the error table to determine the correctlocation and dip of a reflection from an inaccurately migrated image.

FIG. 3 also indicates that the present invention can be implemented inembodiments involving depth migration. Depth migration is frequentlyused to migrate seismic data in areas having a laterally varyingmigration velocity. In such areas, migration velocities are requiredthat accurately reproduce traveltimes for all raypaths to all dips,rather than for a subset of traveltimes corresponding to some chosendips. In depth migration applications, the present invention provides amethod of finding more accurate velocity models than have previouslybeen possible, and simultaneously allows for the measurement ofmigration error for all dips.

In depth migration applications, conventional velocity analysis methodsare used to produce a velocity model, step 70 in FIG. 3. These methodsgenerally involve using the surface seismic data in an optimizationroutine to develop a velocity model for the entire subsurface domain ofinterest. The optimization objective is to accurately reproducetraveltimes for all raypaths, rather than a subset of raypaths as is ofprincipal interest in time migration. These and other suitable velocitymodel generation methods will be well known to those skilled in the art.

As discussed above in conjunction with FIG. 1, the limitation of thevelocity models which result from these methods is that raypaths 11, 15aand 15b do not accurately characterize the raypaths used in migration.However, the offset checkshot survey raypaths, 19 in FIG. 2, overcomethat limitation. As a result, by using the offset checkshot survey data,the present invention allows more accurate velocity models to bedetermined from conventional velocity model generation methods. Oncethat model has been determined, step 70 in FIG. 3, the depth migrationproceeds, step 72. Because the model is more accurate, all dips in themigration domain are more accurately migrated than has previously beenpossible.

To the extent that the velocity model nevertheless produces traveltimesthat are inconsistent with the measured traveltimes, some dips will bemispositioned. The same error quantification procedure discussed abovein conjunction with time migration, steps 76 through 86, can be employedin conjunction with the depth migration to determine the amount ofmigration error at borehole 8. As in time migration, the computed errorscan be used to obtain a geologic interpretation that will be more robustthan that obtained from a conventional depth migration.

The migration velocity model building process discussed above inconjunction with time migration could also be used to build the velocitymodel for a depth migration application of the present invention (notshown in FIG. 3). In such a case, path 54 would lead directly to stepsidentical to steps 58-64, which would replace step 70. An example of anapplication of this embodiment of the present invention would be wherespecific reflector dips are present which the analyst desires tooptimally migrate, but where the time migration assumption of laterallyinvariant velocities is not applicable.

If the analyst's decision at step 46 of FIG. 3 is to employ a migrationmethod involving traveltimes rather than velocity inputs, via path 48,the flowchart of FIG. 6 depicts the steps that would be followed in twoadditional embodiments of the present invention. Such a decision mightbe involved if the analyst requires a more accurate migration result,and is prepared to accept the typically higher cost that is generallyinvolved. Traveltime migrations generally assume an isotropic medium,although that is not a requirement of the steps depicted in FIG. 6.

Typically, traveltimes are determined from raytracing through a velocitymodel. However, that approach has several limitations, including thatvelocity models are often inaccurate, raytracing programs do not alwaysaccount for all physical effects, such as anisotropy, and raytracingprograms usually calculate only the first arrival times, whereas laterarrivals may be more important. Because the offset checkshot data of thepresent invention are a direct measurement of traveltimes required foraccurate migration, the invention provides a method for avoiding theselimitations. In addition, avoiding the derivation of a migrationvelocity model is beneficial in that the derivation can be acomputationally costly and labor intensive part of migrating seismicdata.

Because offset checkshot traveltimes cannot generally be measured forevery point in the region to be migrated, traveltime interpolation mustbe employed before the migration can proceed. If the offset checkshottraveltimes have been gathered at a sufficient number of locationswithin the imaging region, conventional interpolation methods can beemployed, step 92 in FIG. 6. As will be understood to those skilled inthe art, a sufficient number of locations will have been involved wheninterpolating a subset of the checkshot data reproduces measurementlocations not included in the subset used in the interpolation within areasonable, prespecified degree of accuracy. Such conventional methodsas linear interpolation and cubic spline techniques will be appropriatefor this interpolation step.

One application of this embodiment of the present method is depicted inFIG. 7. In this plan view of surface 2, a plurality of boreholes 8a-ehave been previously drilled in the region of a feature to be imaged(not shown). OCS data for receivers (not shown) in each borehole 8a-ewere obtained from a grid of OCS sources 18. The grid of sources 18 doesnot need to be identically located along surface 2 for the OCS datacorresponding to each borehole 8a-e, and due to field measurementconstraints, such as equipment cost and availability, will often not beidentical. The benefit of the OCS data in this example, as discussedabove, is that the OCS grid can be relatively sparsely spaced, both asto source spacing and as to receiver spacing. This results from the OCSdata's use for traveltimes, and not for imaging.

The OCS data in this example are used to interpolate measuredtraveltimes to the locations at which imaging is to occur. This willgenerally involve at least two interpolations. The first interpolationwill be along surface 2. For example, location 32 in FIG. 7 is thelocation of an imaging source for the data from which the migrationimage will be derived. However, location 32 is not the location of anOCS source. Therefore, to obtain traveltimes from location 32 to the OCSreceivers in each well 8a-e, an interpolation of measured traveltimesfrom the nearest OCS sources must be performed. In FIG. 7, OCS sources18a, 18b, 18c, and 18d are used to determine the traveltimes fromlocation 32 to the locations of the OCS receivers in each borehole 8a-e.

The second interpolation is between OCS receivers in each well. Asdiscussed above, the OCS receivers in boreholes 8a-e will be relativelysparsely spaced, and will generally not be coincident with all locationswhere a migrated image is desired to image all subsurface regions ofinterest. Therefore, an interpolation will be required betweentraveltimes measured in boreholes 8a-e to the locations at whichmigration images are to be calculated. Procedures to perform thisinterpolation will be known to those skilled in the art.

This embodiment of the present method may also be usefully applied tosingle well OCS data, for example when an assumption of traveltimelateral invariance is appropriate. Other applications will be apparentto those skilled in the art.

When the conventional interpolations, step 94, have been completed, themigration proceeds, step 96. The image formed in step 98 will accuratelyposition reflector dips at the offset checkshot receiver locations.Because no velocity model has been employed, the present inventionoffers that accurate result without requiring an error quantificationanalysis. The accuracy of other parts of the image, e.g. reflector dipsat other than the offset checkshot receiver locations, hinges only onthe accuracy of the interpolation method.

This conventional interpolation-based migration method will be mostuseful for accurate imaging of limited subsurface regions sinceacquiring sufficient offset checkshot survey data over large regionswill generally be too costly. One possible application would be toaccurately image a small region near a known reservoir. Other possibleapplications will be known to those skilled in the art.

Offset checkshot traveltimes can be used to migrate over largersubsurface regions using more sophisticated interpolation procedures, asoutlined in the embodiment following path 90 in FIG. 6. This embodimentinvolves use of a migration velocity model to guide the interpolation ofthe offset checkshot traveltimes, and is directed at applications inwhich conventional interpolation cannot be employed. The velocity modelguides the interpolation, but is not otherwise a direct part of themigration.

A migration velocity model is computed using conventional methods, step100. Such methods, as discussed above, will be well known to thoseskilled in the art. However, as discussed above in conjunction with step70, it will generally be desirable to incorporate the offset checkshotsurvey data into the velocity model computation.

Next, step 102, traveltimes are computed by raytracing through thisvelocity model. Computed traveltimes which correspond to the sources andreceivers in the offset checkshot survey are compared to the measuredoffset checkshot traveltimes, and traveltime errors are calculated, step104. These errors are the measured traveltimes minus the calculatedtraveltimes. Note that this step differs from step 84 above in that onlya traveltime error is calculated, not an actual migration error vectoras was calculated in that step.

The traveltime errors are next interpolated to migration raypaths notincluded in the offset checkshot survey data, step 106. As demonstratedin FIG. 8, the interpolation procedure to be used depends upon the typeof error expected. For image point locations corresponding to the sourceand receiver raypaths in the offset checkshot survey data, a traveltimeerror estimate, 120 in FIG. 8, results from step 104. If the errors arebelieved to be caused by large scale phenomena, such as anisotropy, andthe phenomena are not expected to vary rapidly, conventionalinterpolation methods such as described above may be satisfactorilyapplied to the errors. Such a smoothly varying error function isdepicted as curve 122 in FIG. 8.

If, on the other hand, the errors are expected to be due to small scaleeffects which may exhibit rapid spatial variation, the analyst may optto set the error to zero except in the immediate neighborhood of theimage point location. This type of error function is depicted as curve124 in FIG. 8. An example of a situation in which the error is locallyvariable may be in the proximity of salt domes where the measuredtraveltimes may be greatly influenced by the local, out-of-planegeometry of the salt.

Once an appropriate error function has been determined, the migrationtraveltimes computed in step 102 of FIG. 6 are corrected by adding theinterpolated error, step 108. The migration is performed using thecorrected traveltimes, step 110. The corrected traveltimes guaranteeaccurate migration at the borehole of all reflector dips, step 112, andfor that reason no migration error computation is required.

It will be understood by those skilled in the art that the presentinvention is applicable to both on land and offshore operations. Anytype of on land or marine seismic source may be used to generate theseismic signals. It will be further understood that for on landoperations the seismic source is often buried a distance up to 100 feetor more below the actual surface of the earth so that the seismic signalis generated below the weathered surface layers of earth which cangreatly attenuate seismic signals. All such seismic sources are withinthe scope of the present invention. Furthermore, an inverse offsetcheckshot configuration is also within the scope of the invention. Inthat configuration the receivers would be placed on or below the earth'ssurface, or in an overlying body of water, and the sources would beplaced in a borehole. Therefore, it should be understood that theinvention is not to be unduly limited to the foregoing which has beenset forth for illustrative purposes. Various modifications andalternatives will be apparent to those skilled in the art withoutdeparting from the true scope of the invention, as defined in thefollowing claims.

What is claimed is:
 1. A method for migrating seismic data acquired from dipping reflectors, said method comprising the steps of:(a) acquiring offset checkshot data from an offset checkshot survey of a subsurface region adjacent to said dipping reflectors, said offset checkshot survey having at least one checkshot source and at least one checkshot receiver positioned such that the raypaths of said offset checkshot data are geometrically similar to the migration raypaths to be used in migrating said seismic data; (b) determining direct arrival traveltimes from said offset checkshot data; (c) interpolating said direct arrival traveltimes to determine migration traveltimes; and (d) using said migration traveltimes to migrate said seismic data.
 2. The method of claim 1, wherein said subsurface region has a borehole therein adjacent to said dipping reflectors, and wherein said checkshot sources are located at or near the surface of the earth and said checkshot receivers are located in said borehole.
 3. The method of claim 2, wherein said seismic data was acquired with at least one imaging source and at least one imaging receiver, and wherein said offset checkshot data involves at least one grid of checkshot sources, and further involves at least two boreholes, each of said boreholes having at least one checkshot receiver located therein, said interpolation comprising the steps of:(a) interpolating from said grid of checkshot sources to the location of at least one imaging source; and (b) interpolating from said checkshot receivers to the location of at least one imaging receiver.
 4. The method of claim 1, wherein said subsurface region has a borehole therein adjacent to said dipping reflectors, and wherein said checkshot receivers are located at or near the surface of the earth and said checkshot sources are located in said borehole.
 5. A method for migrating seismic data acquired from dipping reflectors, said method comprising the steps of:(a) acquiring offset checkshot data from an offset checkshot survey of a subsurface region adjacent to said dipping reflectors, said offset checkshot survey having at least one checkshot source and at least one checkshot receiver positioned such that the raypaths of said offset checkshot data are geometrically similar to the migration raypaths to be used in migrating said seismic data; (b) determining direct arrival traveltimes from said offset checkshot data; (c) using said direct arrival traveltimes to correct errors in migration traveltimes, wherein said migration traveltimes are derived from a migration velocity model; and (d) using said corrected migration traveltimes to migrate said seismic data.
 6. The method of claim 5, wherein said migration traveltimes are obtained from raytracing through said migration velocity model, and wherein said errors are the differences between said raytraced traveltimes and said direct arrival traveltimes.
 7. The method of claim 5, further comprising the step of interpolating said errors to migration raypaths not included in said offset checkshot data.
 8. The method of claim 7, wherein said interpolation involves determination of an error function.
 9. A method for migrating seismic data acquired from dipping reflectors, said method comprising the steps of:(a) acquiring offset checkshot data from an offset checkshot survey of a subsurface region adjacent to said dipping reflectors, said offset checkshot survey having at least one checkshot source and at least one checkshot receiver positioned such that the raypaths of said offset checkshot data are geometrically similar to the migration raypaths to be used in migrating said seismic data; (b) determining direct arrival traveltimes from said offset checkshot data; (c) using said direct arrival traveltimes to determine a migration velocity model; (d) migrating said seismic data using said migration velocity model; and (e) using said-offset checkshot survey data and said migration velocity model to determine a migration error table for said migrated seismic data.
 10. The method of claim 9, wherein said determination of said migration error table comprises the steps of:(a) sorting said offset checkshot data into common receiver order and generating a traveltime curve for each checkshot receiver as a function of checkshot source location; and (b) for each source-receiver pair in said offset checkshot data,(i) measuring a time dip for said checkshot source on said traveltime curve for said checkshot receiver, (ii) using said time dip, tracing a raypath from said checkshot source through said migration velocity model until the traveltime for said raypath is equal to said direct arrival traveltime for said source-receiver pair, and (iii) determining a migration error vector between said checkshot receiver location and the endpoint of said raypath.
 11. The method of claim 10, wherein said migration error table contains reflector location error and reflector dip error.
 12. The method of claim 9, said method further comprising the steps of:(a) preselecting at least one of said dipping reflectors; (b) determining a checkshot source location for each said preselected dipping reflector; and (c) for each said checkshot source location, determining direct arrival traveltime weighting factors, wherein said determination of said migration velocity model uses said weighting factors and said direct arrival traveltimes.
 13. The method of claim 12, wherein said determination of said migration error table comprises the steps of:(a) sorting said offset checkshot data into common receiver order and generating a traveltime curve for each checkshot receiver as a function of checkshot source location; and (b) for each source-receiver pair in said offset checkshot data, traveltime for said raypath is equal to said direct arrival traveltime for said source-receiver pair, and(iii) determining a migration error vector between said checkshot receiver location and the endpoint of said raypath.
 14. The method of claim 13, wherein said migration error table contains reflector location error and reflector dip error. 